No smooth sailing on the Gulf Coast

Gordon Cope, Contributing Editor, explains how producers on the US Gulf Coast are navigating a maze of obstacles.

The US Gulf Coast has been a mainstay of North American energy for more than a century. In addition to massive offshore fi elds, the shale revolution has created one of the largest single sources of oil and gas in the world. But the region is facing major environmental, regulatory and market challenges that complicate its prospects.

Offshore

While capital expenditures for greenfi eld projects in the Gulf of Mexico have been reduced over the last several years through modular design and other engineering innovations, the most cost-effi cient method is to explore for new reserves near existing projects. In April 2021, BP announced an oil discovery at its Puma West prospect in Green Canyon Block 821, located over 200 km off the Louisiana coast. While the company did not estimate the size of the discovery, it noted that its exploratory well had encountered potentially commercial quantities of crude in high-quality reservoirs similar to nearby Miocene fi elds. The discovery sits just west of the Mad Dog platform, facilitating a tie-in to existing infrastructure.

In May 2021, Shell announced a signifi cant discovery at its Leopard prospect, located almost 400 km southeast of Houston, Texas.

The well encountered 183 m net oil in multiple levels. The discovery is located within the Perdido Corridor, which encompasses the company’s Great White, Silvertip and Tobago fi elds.

In June 2021, BP announced the start-up of the Manuel project, which includes a subsea production system that ties two new wells into the Na Kika platform, located 140 miles off the coast of Louisiana. The project originally held over 300 million bbl of oil equivalent (boe), located in fi ve adjacent oil and gas fi elds. Since 2003, it has been producing approximately 130 000 bpd and 500 million ft3/d. The new wells will add 20 100 boe/d to output.

Onshore

In June 2021, the West Texas Intermediate (WTI) benchmark surged above US$70/bbl, a mark that makes most shale oil profi table. Shale basins throughout the US are rebounding, but the greatest recovery is in the Permian. Prior to the pandemic, production stood at around 4.8 million bpd. It dropped to below 4.3 million bpd by mid-2020, but by mid-2021 it had climbed to 4.6 million bpd, with drilled but uncompleted wells (DUCs) falling signifi cantly.

There is still considerable potential for upside, but several caveats are in order. January 2020 saw an all-time high of 13.1 million bpd US production; as of mid-2021, that level is still sitting 2 million bpd below, at 11 million bpd. Even with thousands of shale oil DUCs still on inventory, reaching the previous record would require massive investments; producers, especially shale operators, are more focused on cutting debt and rewarding stockholders.

The consolidation in the Permian basin based on stock deals (rather that outright purchases) is part of this focus. In April 2021, Pioneer Natural Resources merged with Double Point Energy in a US$6.4 billion deal. The acquisition gives Pioneer 97 000 acres of largely-undrilled, non-federal land in the Permian basin with a potential for up to 100 000 bpd production.

Refineries

The precipitous fall in fuel demand due to COVID-19 has refi ners throughout the world critically examining under-performing assets, and the US Gulf Coast (USGC) is no exception. Over the course of the last two years, Shell has mothballed its Convent refi nery in Louisiana and sold its controlling interest in the Deer Park refi nery in Texas. When it is fi nished, Shell will have one refi nery remaining in the region – the 227 400 bpd plant in Norco, Louisiana, 40 km west of New Orleans. The facility produces ethylene and propylene in addition to fuels; the chemicals are used as feedstock for Shell’s nearby Norco and Geismar petrochemical plants.

Pipelines

While pipeline operators have largely met the growth of crude production in the Permian basin, servicing the related associated natural gas production has lagged. Several new gas pipelines have recently entered service, however. Kinder Morgan’s Permian Highway Pipeline came online in early 2021, moving up to 2.1 billion ft3/d from the Waha hub in West Texas to the Gulf Coast. Whitewater’s Aqua Blanca began operations in early 2021, transporting 1.8 billion ft3/d to the Waha hub, where it is expected to move south to export hubs along the Whistler Pipeline when it is completed in late 2021.

In January 2021, Double E submitted a request to the US Federal Energy Regulatory Commission (FERC) to begin construction on the Double E pipeline, a 135 mile conduit designed to move up to 1.35 billion ft3/d of natural gas from the Summit Lane Plant in the Permian basin to the Waha Hub. Double E has secured ExxonMobil as an anchor shipper (which also holds a 30% stake in the project). The line is expected to enter service late in 2021.

In light of the cancellation of the Keystone XL pipeline, companies are working on supplying suffi cient alternate capacity to deliver heavy Canadian crude to USGC refi neries. In addition to incremental gains on existing Enbridge and TC systems, Plains All American and partners are working to reverse the Capline pipeline. Originally built in 1967 to move imported crude north from Louisiana to the Patoka hub in Illinois, it eventually became a white elephant as domestic sources were developed. Now, the 1017 km, 40 in. pipeline is being reconfi gured to deliver up to 650 000 bpd to the Gulf Coast. First portions are expected to begin operations early in 2022, with scale-up proceeding throughout the year.

Petrochemicals

A major portion of the US’ 40 million tpy ethylene capacity is located in the Gulf Coast. Total’s new Baystar 1 million tpy ethylene cracker in Port Arthur, Texas, began start-up in June 2021. The JV with Borealis is designed to supply a new 400 000 tpy polyethylene plant near the Houston Ship Channel, as well as an adjacent 625 000 tpy plant expected to come online in early 2022. Over 8 million tpy of new capacity is being planned for 2021 and beyond.

Weather had a recent major impact on Gulf Coast petrochemical plants. In February 2021, a polar vortex hit the state of Texas (see ‘Batten down the hatches’ sidebar). While electricity blackouts made the news, another signifi cant disruption had longer-term impact. More than 60% of polyvinyl chloride (PVC) production capacity was still out of operation over a month after the storm. PVC serves as a vital feedstock to the production of housing materials, cable insulation and car parts; the disruption sent manufacturers in the US and abroad scrambling to keep their factories open.

LNG

The LNG market has had a wild ride over the last year. When the COVID-19 pandemic wiped out LNG demand in Asia in mid-2020, several plants in the USGC temporarily shut down, including Freeport’s three trains in Texas. By 2021, however, demand had roared back; in March 2021, LNG exports averaged a record 10.5 billion ft3/d. Freeport not only brought all its capacity back online, but ran almost 20% in excess of its 12.3 million tpy nameplate capacity. Freeport is now looking at adding a fourth, 5 million tpy train, with a fi nal investment decision (FID) expected in 2022, and a start-up in 2026.

Additionally, several aspects point to longer term growth. US suppliers have developed contracts that are not linked to oil-pricing; as prices rebound, spot shipments

become more competitive. Major LNG consumers in Asia are also keen to diversify sources in order to reduce risks associated with potential supply disruptions in the Middle East, and European consumers are wary of over-reliance on Russian supplies. Many consuming nations (in Asia, especially) are eager to switch from coal-fi red utilities to cleaner-burning natural gas. While the price for Henry Hub gas has risen over the last year, US LNG producers still remain well within competitive international pricing.

Challenges

The election of President Joe Biden is having a signifi cant impact on energy in North America as the White House focuses on climate change. It imposed a freeze on new oil and gas drilling permits on federal lands, as well as a moratorium on lease sales. The Bureau of Ocean Energy Management (BOEM) subsequently cancelled a March 2021 lease sale that would have offered 78.2 million acres in the Gulf of Mexico. Approximately 12% of US production comes from federal lands; if the freeze becomes a permanent ban, states such as Wyoming, New Mexico and the offshore Gulf of Mexico would be signifi cantly impacted over time.

The future

Many within the US oil and gas sector are taking the shift in climate priorities to heart, and are seeking ways to proactively meet environmental goals. In June 2021, The Greater Houston Partnership, a business group that represents over 900 companies, released a McKinsey study that tabulated over 500 000 new jobs associated with a proactive energy transition policy designed to leverage existing infrastructure. “If we move forward in the energy transition in a smart and resilient way, we will stay at the forefront of the energy sector,” said Houston Mayor Sylvester Turner. “The City of Houston’s innovation and adaptability will be key as the energy industry diversifi es.”

A major key to the transition could be a public-private carbon storage project to collect CO2 from Gulf Coast petrochemical plants and sequester them beneath the Gulf of Mexico. ExxonMobil has proposed a massive plan to capture CO2 from the 50 largest industrial emitters located on the 80 km long Houston Ship Channel and then piping it to offshore reservoirs located almost 2 km below the ocean fl oor. The plan would cost US$100 billion in order to store 50 million t by 2030, with an additional 50 million t over the following decade.

Houston could also become a low-carbon hydrogen hub. The greater metropolitan area is home to one-third of US hydrogen production; it contains a network of 48 hydrogen plants and over 900 miles of hydrogen pipelines. “The region’s enormous port, rail and air infrastructure represents a signifi cant platform for implementing large-scale decarbonisation initiatives,” noted Bobby Tudor, Chairman of the Partnership’s Houston Energy Transition Initiative.

In the short-term, North America’s oil and gas sector has benefi ted tremendously from the discipline shown by OPEC+ over the last year, its members largely sticking to self-imposed quotas that have allowed a huge glut to dissipate and prices to stabilise above US$60. In July 2021, OPEC+ ministers reached consensus on a new deal, agreeing to boost overall production by a total of 2 million bpd by the end of 2021, as COVID-19 lockdowns recede and demand increases. The group also stated that it plans to end all output restrictions by September 2022.

In the longer term, an energy transition toward renewables, as well as a shift from internal combustion engines (ICE) to electric vehicles (EVs), will eventually reduce demand for fossil fuels. In the meantime, USGC producers are reaping billions of dollars in cash fl ow; those with vision are planning for a future in which they will play an integral part in new forms of energy and new ways to meet climate challenges.

Batten down the hatches

In February 2021, a polar vortex hit the state of Texas, causing gas wells to freeze and production to drop from around 24 billion ft3/d to as low as 11 billion ft3/d. Cut off from fuel, the power grid failed in major metropolitan areas, plunging millions into the cold and dark. By the time power had been restored, the state had lost billions in revenues and tallied over 100 fatalities.

The weather event hit petrochemical facilities hard, taking an estimated 30 million t of ethylene capacity offl ine, the vast majority located along the Texas coast. Dow Chemical, Formosa Plastics, BASF and other major manufacturers declared force majeure and instigated shutdowns at over three dozen facilities in the wake of the cold snap. Because of complications arising due to the unplanned shutdowns, more than 60% of PVC production capacity remained offl ine for over a month after the storm. Manufacturers who rely on the chemical feedstock found themselves in a bidding war to keep their plants open; polymer grade prices (PGPs) rose to an all-time high of US$1.25/lb in late February 2021, before falling back to under US¢80/lb in March.

Severe weather has also affected refi neries. When a massive rain and lightning storm dumped up to 10 in. of rain and engulfed Port Arthur, Texas, several Gulf Coast refi neries had to slow production. Total’s 225 500 bpd Port Arthur refi nery in Texas went offl ine after a power loss, a transformer blowout at Motiva’s 607 000 bpd Port Arthur refi nery took a coker offl ine, and a catalytic reformer shut down production at Valero’s 335 000 bpd Port Arthur facility.

Hurricanes are an unfortunate annual event in the Gulf of Mexico. The hurricane season, which runs from June to November, saw record numbers of major events strike the USGC region last year. In August 2020, almost 300 offshore platforms were evacuated ahead of Hurricane Laura, shutting in over half of all gas production and 80% of oil production. Onshore, six refi neries representing over 2 million bpd capacity were shuttered. When the hurricane made landfall in Louisiana, it damaged infrastructure at the Phillips 66 and Citgo refi neries, partially reducing output for several weeks. The National Hurricane Center expects an active hurricane season in 2021; in June 2021, tropical storm Claudette forced Chevron to evacuate its Tahiti platform.